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MarketScreener Homepage  >  Equities  >  Nasdaq  >  Xcel Energy    XEL

XCEL ENERGY

(XEL)
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XCEL ENERGY : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

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07/31/2020 | 01:04pm EDT
The following discussion and analysis by management focuses on those factors
that had a material effect on Xcel Energy's financial condition, results of
operations and cash flows during the periods presented, or are expected to have
a material impact in the future. It should be read in conjunction with the
accompanying unaudited consolidated financial statements and the related notes
to consolidated financial statements. Due to the seasonality of Xcel Energy's
operating results, quarterly financial results are not an appropriate base from
which to project annual results. The demand for electric power and natural gas
is affected by seasonal differences in the weather. In general, peak sales of
electricity occur in the summer months, and peak sales of natural gas occur in
the winter months. As a result, the overall operating results may fluctuate
substantially on a seasonal basis. Additionally, Xcel Energy's operations have
historically generated less revenues and income when weather conditions are
milder in the winter and cooler in the summer.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance
with GAAP, as well as certain non-GAAP financial measures such as electric
margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally,
a non-GAAP financial measure is a measure of a company's financial performance,
financial position or cash flows that excludes (or includes) amounts that are
adjusted from measures calculated and presented in accordance with GAAP. Xcel
Energy's management uses non-GAAP measures for financial planning and analysis,
for reporting of results to the Board of Directors, in determining
performance-based compensation, and communicating its earnings outlook to
analysts and investors. Non-GAAP financial measures are intended to supplement
investors' understanding of our performance and should not be considered
alternatives for financial measures presented in accordance with GAAP. These
measures are discussed in more detail below and may not be comparable to other
companies' similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and
purchased power expenses. Natural gas margin is presented as natural gas
revenues less the cost of natural gas sold and transported. Expenses incurred
for electric fuel and purchased power and the cost of natural gas are generally
recovered through various regulatory recovery mechanisms. As a result, changes
in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful
basis for evaluating our operations because they exclude the revenue impact of
fluctuations in these expenses. These margins can be reconciled to operating
income, a GAAP measure, by including other operating revenues, cost of sales -
other, O&M expenses, conservation and DSM expenses, depreciation and
amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities
or other agreements to issue common stock (i.e., common stock equivalents) were
settled. The weighted average number of potentially dilutive shares outstanding
used to calculate Xcel Energy Inc.'s diluted EPS is calculated using the
treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings
(net income) for certain items.
Ongoing diluted EPS is calculated by dividing the net income or loss of each
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS
for each subsidiary is calculated by dividing the net income or loss of such
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel
Energy's core earnings and underlying performance. We believe these measurements
are useful to investors to evaluate the actual and projected financial
performance and contribution of our subsidiaries.
For the three and six months ended June 30, 2020 and 2019, there were no such
adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings
for these periods.
                             Results of Operations


The only common equity securities that are publicly traded are common shares of
Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do
not represent a direct legal interest in the assets and liabilities allocated to
such subsidiary but rather represent a direct interest in our assets and
liabilities as a whole.
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GAAP and ongoing diluted EPS for Xcel Energy:

                                                Three Months Ended June 30                               Six Months Ended June 30
Diluted Earnings (Loss) Per Share                2020                 2019                2020                  2019
PSCo                                       $       0.21$     0.20$    0.45$       0.47
NSP-Minnesota                                      0.22                 0.19               0.43                  0.41
SPS                                                0.14                 0.11               0.22                  0.22
NSP-Wisconsin                                      0.02                 0.02               0.09                  0.06
Equity earnings of unconsolidated
subsidiaries                                       0.01                 0.01               0.02                  0.02
Regulated utility (a)                              0.60                 0.53               1.20                  1.18
Xcel Energy Inc. and Other                        (0.07)               (0.06)             (0.10)                (0.11)

Total (a)                                  $       0.54$     0.46$    1.10$       1.07


(a)  Amounts may not add due to rounding.
Summary of Earnings
Xcel Energy - Xcel Energy's earnings increased $0.08 per share for the second
quarter of 2020 and $0.03 per share year-to-date. Earnings reflect management's
actions to reduce O&M to offset the impact from COVID-19 and favorable weather,
partially offset by higher depreciation and interest charges. Income taxes were
lower primarily due to higher PTCs, which are credited to customers, resulting
in lower electric margin and do not materially impact earnings.
PSCo - Earnings increased $0.01 per share for the second quarter of 2020 and
decreased $0.02 per share year-to date. The decrease in year-to-date earnings
was driven by lower sales and demand revenue primarily due to COVID-19, higher
depreciation, interest charges and lower natural gas margins due to unfavorable
weather, partially offset by higher AFUDC, an increase in electric margins
(regulatory outcomes offset lower sales due to COVID-19) and lower O&M.
NSP-Minnesota - Earnings increased $0.03 per share for the second quarter of
2020 and $0.02 year-to-date. The increase in year-to-date earnings primarily
reflects lower O&M and income taxes, partially offset by lower electric margins
(reflecting lower sales from COVID-19) and natural gas margins as well as higher
depreciation. Lower electric margins were due primarily to increased PTCs flowed
back to customers (offset in income tax) and decreased sales, partially offset
by non-fuel riders.
SPS - Earnings increased $0.03 per share for the second quarter of 2020 and were
flat year-to-date. Year-to-date earnings were driven by lower O&M and income
taxes, offset by lower electric margin and increased depreciation. Lower
electric margins were attributable to lower sales from COVID-19, increased PTCs
flowed back to customers (offset in income tax) and a 2019 NMPRC revised order
eliminating a $10 million retroactive refund of tax reform benefits, partially
offset by an increase in wholesale transmission revenue.
NSP-Wisconsin - Earnings were flat for the second quarter of 2020 and increased
$0.03 per share year-to-date. The increase in year-to-date earnings was driven
by lower O&M and income taxes, as well as higher electric margin (due primarily
to regulatory outcomes which offset lower sales from COVID-19), partially offset
by lower natural gas margins due to unfavorable weather and increased
depreciation.
Xcel Energy Inc. and Other - Primarily includes financing costs at the holding
company.
Changes in GAAP and Ongoing Diluted EPS
Components significantly contributing to changes in 2020 EPS compared with the
same period in 2019:
Diluted Earnings (Loss) Per Share                         Three Months Ended June 30           Six Months Ended June 30
GAAP and ongoing diluted EPS - 2019                      $                  0.46             $                 1.07

Components of change - 2020 vs. 2019
Lower ETR (a)                                                               0.07                               0.10
Lower O&M                                                                   0.05                               0.08
Higher AFUDC                                                                0.03                               0.04
Higher electric margin (b)                                                  0.02                               0.02
Higher depreciation and amortization                                       (0.05)                             (0.09)
Higher interest charges                                                    (0.03)                             (0.04)
Lower natural gas margins                                                      -                              (0.03)
Lower other income (expense), net                                              -                              (0.02)
Other (net)                                                                (0.01)                             (0.03)
GAAP and ongoing diluted EPS - 2020                      $                  0.54             $                 1.10


(a)  Includes PTCs and tax reform regulatory amounts, which are primarily offset
in electric margin.
(b)  The period-over-period change in electric margin was negatively impacted by
reductions in sales and demand. See table below:
Diluted Earnings (Loss) Per Share                    Three Months Ended June 30           Six Months Ended June 30
Electric margin (excluding reductions in
sales and demand)                                   $                  0.09             $                 0.09
Reductions in sales and demand (a)                                    (0.07)                             (0.07)
Higher electric margins                             $                  0.02             $                 0.02



(a) Sales decline excludes weather impact, net of decoupling/sales true-up and
decrease in demand revenue is net of sales true-up.
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and
expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings -Unusually hot
summers or cold winters increase electric and natural gas sales, while mild
weather reduces electric and natural gas sales. The estimated impact of weather
on earnings is based on the number of customers, temperature variances, the
amount of natural gas or electricity historically used per degree of temperature
and excludes any incremental related operating expenses that could result due to
storm activity or vegetation management requirements. As a result, weather
deviations from normal levels can affect Xcel Energy's financial performance.
Degree-day or THI data is used to estimate amounts of energy required to
maintain comfortable indoor temperature levels based on each day's average
temperature and humidity. HDD is the measure of the variation in the weather
based on the extent to which the average daily temperature falls below 65°
Fahrenheit. CDD is the measure of the variation in the weather based on the
extent to which the average daily temperature rises above 65° Fahrenheit. Each
degree of temperature above 65° Fahrenheit is counted as one CDD, and each
degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel
Energy's more humid service territories, a THI is used in place of CDD, which
adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the
usage of Xcel Energy's residential and commercial customers. Industrial
customers are less sensitive to weather.

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Normal weather conditions are defined as either the 10, 20 or 30-year average of
actual historical weather conditions. The historical period of time used in the
calculation of normal weather differs by jurisdiction, based on regulatory
practice. To calculate the impact of weather on demand, a demand factor is
applied to the weather impact on sales. Extreme weather variations, windchill
and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD, CDD and THI:
                               Three Months Ended June 30                                                                            Six Months Ended 

June 30

                2020 vs.               2019 vs.                2020 vs.                2020 vs.                2019 vs.                2020 vs.
                 Normal                 Normal                   2019                   Normal                  Normal                   2019
HDD                   2.2  %                 16.9  %                (11.8) %                 (4.1) %                 12.8  %               (14.4) %
CDD                  22.4                   (45.2)                  191.2                    22.5                   (45.5)                 139.9
THI                  15.0                   (26.7)                   63.6                    14.7                   (26.9)                  63.6


Weather - Estimated impact of temperature variations on EPS compared with normal
weather conditions:
                                  Three Months Ended June 30                                                      Six Months Ended June 30
                         2020 vs.          2019 vs.          2020 vs.          2020 vs.         2019 vs.            2020 vs.
                          Normal            Normal             2019             Normal           Normal               2019
Retail electric        $   0.028$ (0.024)$  0.052$ 0.017$ (0.005)$    0.022
Decoupling and sales
true-up                   (0.014)            0.006            (0.020)          (0.009)            0.001              (0.010)
Electric total         $   0.014$ (0.018)$  0.032$ 0.008$ (0.004)$    0.012
Firm natural gas           0.001             0.004            (0.003)          (0.006)            0.022              (0.028)
Total                  $   0.015$ (0.014)$  0.029$ 0.002$  0.018$   (0.016)

Sales Growth (Decline) - Sales growth (decline) for actual and weather-normalized sales in 2020 compared to the same period in 2019:

                                                                                           Three Months Ended June 30
                                              PSCo                   NSP-Minnesota                   SPS                  NSP-Wisconsin                 Xcel Energy
Actual (a)
Electric residential                             13.5  %                         10.2  %               13.4  %                        10.8  %                    11.9  %
Electric C&I                                     (8.3)                          (13.2)                 (7.5)                         (12.3)                     (10.2)
Total retail electric sales                      (1.7)                           (6.6)                 (4.4)                          (6.5)                      (4.5)
Firm natural gas sales                          (13.0)                            0.4                      N/A                        (3.8)                      (8.5)


                                                                                           Three Months Ended June 30
                                            PSCo (b)                NSP-Minnesota                   SPS                  NSP-Wisconsin                 Xcel Energy
Weather-normalized (a)
Electric residential                             6.1  %                          5.7  %                3.3  %                         4.9  %                     5.4  %
Electric C&I                                   (10.4)                          (14.2)                 (8.6)                         (13.3)                     (11.5)
Total retail electric sales                     (5.4)                           (8.5)                 (6.9)                          (8.6)                      (7.1)
Firm natural gas sales                          (7.4)                            2.7                      N/A                         3.1                       (3.9)


                                                                                            Six Months Ended June 30
                                              PSCo                 NSP-Minnesota                   SPS                   NSP-Wisconsin                 Xcel Energy
Actual (a)
Electric residential                             5.7  %                        2.1  %                  5.4  %                        1.0  %                      3.8  %
Electric C&I                                    (4.0)                         (8.5)                   (2.2)                         (6.4)                       (5.4)
Total retail electric sales                     (1.0)                         (5.4)                   (1.1)                         (4.3)                       (2.9)
Firm natural gas sales                          (8.2)                        (10.4)                       N/A                      (12.0)                       (9.1)



                                                                                           Six Months Ended June 30
                                           PSCo (b)                 NSP-Minnesota                   SPS                  NSP-Wisconsin                 Xcel Energy
Weather-normalized (a)
Electric residential                             3.4  %                          2.7  %                1.9  %                         3.0  %                     2.9  %
Electric C&I                                    (5.0)                           (8.7)                 (2.7)                          (6.5)                      (5.8)
Total retail electric sales                     (2.4)                           (5.3)                 (2.1)                          (3.8)                      (3.5)
Firm natural gas sales                          (1.4)                            2.6                      N/A                         3.3                        0.2


                                                                                  Six Months Ended June 30 (Leap Year Adjusted)
                                             PSCo (b)                 NSP-Minnesota                   SPS                  NSP-Wisconsin                 Xcel Energy
Weather-normalized (a)
Electric residential                               2.8  %                          2.2  %                1.3  %                         2.4  %                     2.3  %
Electric C&I                                      (5.5)                           (9.2)                 (3.3)                          (7.1)                      (6.4)
Total retail electric sales                       (3.0)                           (5.8)                 (2.7)                          (4.4)                      (4.1)
Firm natural gas sales                            (2.2)                            1.7                      N/A                         2.3                       (0.7)


(a)  Higher residential sales and lower C&I sales were primarily attributable to
COVID-19.
(b)  CPUC approved a historical 10-year weather normalization approach for
retail electric, effective March 1, 2020.
Weather-normalized and leap-year adjusted electric sales growth (decline) -
year-to-date (excluding leap day)
•PSCo - Residential sales rose based on higher use per customer from
stay-at-home mandates and an increased number of customers. The C&I decline was
due to lower use offsetting an increase in the number of C&I customers. The
decline in C&I sales was primarily due to the shutdown of the economy from
COVID-19, decreases in the manufacturing and service industries, partially
offset by an increase in the energy sector.
•NSP-Minnesota - Residential sales growth reflects higher use per customer from
stay-at-home mandates and increased customer additions. The drop in C&I sales
was as a result of customer growth offset by lower use per customer. Decreased
sales to C&I customers were due to the shutdown of the economy from COVID-19 and
declines in the energy, manufacturing and services sectors.
•SPS - Residential sales increased due to customer growth and higher use per
customer from stay-at-home mandates. The decline in C&I sales was due to
shutdowns of the economy from COVID-19, declines in oil and natural gas
extraction due to lower commodity prices and lower manufacturing, agriculture &
food and services.
•NSP-Wisconsin - Residential sales growth was attributable to higher use per
customer from stay-at-home mandates and customer additions. The decline in C&I
was largely due to the shutdown of the economy from COVID-19 and decreased sales
to the manufacturing sector.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) -
year-to-date (excluding leap day)
•Natural gas sales reflect an increase in number of customers combined with
lower customer use due to the shutdown of the economy from COVID-19.

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Electric Margin
Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium used in the
generation of electricity. However, these price fluctuations have minimal impact
on electric margin due to fuel recovery mechanisms that recover fuel expenses.
In addition, electric customers receive a credit for PTCs generated in a
particular period.
Electric revenues and margin:
                                      Three Months Ended June 30                                   Six Months Ended June 30
(Millions of Dollars)                 2020                   2019                  2020                   2019
Electric revenues               $       2,286$      2,249$     4,489$        4,574
Electric fuel and
purchased power                          (833)                  (813)              (1,630)                 (1,727)
Electric margin                 $       1,453$      1,436$     2,859$        2,847


Changes in electric margin:
                                                            Three Months Ended June 30,          Six Months Ended June 30,
(Millions of Dollars)                                              2020 vs. 2019                       2020 vs. 2019
Regulatory rate outcomes (Colorado, Wisconsin and
New Mexico)                                               $                    21               $                 34
Wholesale transmission revenue (net)                                           20                                 25
Non-fuel riders                                                                11                                 24
Estimated impact of weather (net of
decoupling/sales true-up)                                                      21                                  8
PTCs flowed back to customers (offset by a lower
ETR)                                                                          (31)                               (53)
Sales and demand (a)                                                          (47)                               (46)

New Mexico tax reform related regulatory settlement (2019)

                                                                          -                                (10)
Other (net)                                                                    22                                 30
Total increase in electric margin                         $                    17               $                 12


(a)  Sales decline excludes weather impact, net of decoupling/sales true-up and
decrease in demand revenue is net of sales true-up.
Natural Gas Margin
Natural gas expense varies with changing sales and the cost of natural gas.
However, fluctuations in the cost of natural gas has minimal impact on natural
gas margin due to cost recovery mechanisms.
Natural gas revenues and margin:
                                       Three Months Ended June 30                                     Six Months Ended June 30
(Millions of Dollars)                  2020                    2019                  2020                    2019
Natural gas revenues            $          280            $        308$        863$        1,102
Cost of natural gas sold
and transported                            (86)                   (112)                 (371)                   (591)
Natural gas margin              $          194            $        196$        492          $          511

Changes in natural gas margin:

                                                      Three Months Ended June 30,           Six Months Ended June 30,
(Millions of Dollars)                                        2020 vs. 2019                        2020 vs. 2019
Estimated impact of weather                         $                    (2)              $                  (19)
Transport sales                                                           -                                   (2)
Regulatory rate outcomes (Wisconsin)                                      -                                   (2)
Retail sales decline                                                     (2)                                  (1)
Infrastructure and integrity riders                                       4                                    5
Conservation revenue (offset in expenses)                                 2                                    3
Other (net)                                                              (4)                                  (3)
Total decrease in natural gas margin                $                    (2)              $                  (19)


Non-Fuel Operating Expenses and Other Items
O&M Expenses - O&M expenses decreased $36 million, or 6.1%, for the second
quarter and $55 million, or 4.6%, year-to-date, largely reflecting management
actions to reduce costs to offset the impact of lower sales from COVID-19.
Significant changes are summarized as follows:
                                                    Three Months Ended June 30,           Six Months Ended June 30,
(Millions of Dollars)                                      2020 vs. 2019                        2020 vs. 2019
Distribution                                       $                   (20)             $                  (30)
Employee benefits                                                        6                                 (10)
Transmission                                                            (5)                                 (6)
Generation                                                              (4)                                 (6)
Strategic initiatives                                                    -                                   6
Other (net)                                                            (13)                                 (9)
Total decrease in O&M expenses                     $                   (36)             $                  (55)


•Distribution expenses declined due to cost mitigation efforts including
allocation of workforce, material and supply management, performance of
maintenance and other items;
•Employee benefits were lower year-to-date primarily due to change in deferred
compensation liability, offset in Other Income (Expense);
•Transmission expenses declined due to a reduction in labor related amounts and
cost mitigation initiatives;
•Generation expenses were lower from timing of maintenance and overhauls at
power plants and cost mitigation efforts, partially offset by an increase in
wind related amounts;
•Strategic initiative amounts were higher year-to-date due to increased spending
on customer experience transformation program expenses and advanced grid
infrastructure; and
•Other primarily includes deferred amounts associated with the Texas 2019
electric rate case and the outcome of the CPUC's rehearing of the Colorado 2019
electric rate case.
Depreciation and Amortization - Depreciation and amortization increased $34
million, or 7.7%, for the second quarter and $64 million, or 7.3%, year-to-date.
Increase was primarily driven by the Hale, Lake Benton, Foxtail and Blazing Star
I wind facilities going into service, as well as normal system expansion. In
addition, depreciation rates were increased in Colorado and New Mexico as part
of regulatory outcomes in 2020.
Other Income (Expense) - Other income (expense) increased $3 million for the
second quarter and decreased $13 million year-to-date. Decrease is due to the
performance of rabbi trust investments, which is offset in O&M expense (deferred
compensation).


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AFUDC, Equity and Debt - AFUDC increased $19 million for the second quarter and
$23 million year-to-date. Increase was primarily due to additional AFUDC
recorded on various wind projects currently under construction.
Interest Charges - Interest charges increased $19 million, or 10.1%, for the
second quarter and $28 million, or 7.4% year-to-date. Increase was primarily due
to higher debt levels to fund capital investments, partially offset by lower
long-term and short-term interest rates.
Income Taxes - Income taxes decreased $37 million for the second quarter.
Decrease was primarily driven by an increase in wind PTCs and an increase in
plant regulatory differences. Wind PTCs are credited to customers (recorded as a
reduction to revenue) and do not have a material impact on net income. The ETR
was (4.7%) for the second quarter of 2020 compared with 9.2% for the same period
in 2019.
Income taxes decreased $68 million for the first six months of 2020. Decrease
was primarily driven by an increase in wind PTCs, lower pretax earnings and an
increase in plant-related regulatory differences. Wind PTCs are credited to
customers and do not have a material impact on net income. The ETR was (3.4%)
for the first six months ending June 30, 2020 compared with 8.1% for the same
period in 2019.




Public Utility Regulation


The FERC and various state and local regulatory commissions regulate Xcel Energy
Inc.'s utility subsidiaries and WGI. The electric and natural gas rates charged
to customers of Xcel Energy Inc.'s utility subsidiaries and WGI are approved by
the FERC or the regulatory commissions in the states in which they operate.
The rates are designed to recover plant investment, operating costs and an
allowed return on investment. Xcel Energy Inc.'s utility subsidiaries request
changes in rates for utility services through filings with governing
commissions.
Changes in operating costs can affect Xcel Energy's financial results, depending
on the timing of rate case filings and implementation of final rates. Other
factors affecting rate filings are new investments, sales, conservation and DSM
efforts, and the cost of capital. In addition, the regulatory commissions
authorize the ROE, capital structure and depreciation rates in rate proceedings.
Decisions by these regulators can significantly impact Xcel Energy's results of
operations.
Except to the extent noted below, the circumstances set forth in Public Utility
Regulation included in Item 7 of Xcel Energy's Annual Report on   Form 10-K
for the year ended Dec. 31, 2019 and in Item 2 of Xcel Energy's Quarterly Report
on   Form 10-Q   for the quarterly period ended March 31, 2020 appropriately
represent, in all material respects, the current status of public utility
regulation and are incorporated by reference.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
                                            Amount Requested             Filing
 Mechanism          Utility Service          (in millions)                Date               Approval                      Additional Information
                                                                             MPUC
                                                                                                              In November 2019, NSP-Minnesota filed the 2020
  2020 TCR             Electric                   $82                 November 2019           Pending         TCR Rider. The filing included an ROE of 9.06%.
                                                                                                              Timing of an MPUC ruling is uncertain.
                                                                                                              In November 2019, NSP-Minnesota filed the 2020
 2020 GUIC            Natural Gas                 $21                 November 2019           Pending         GUIC Rider with the MPUC. The filing included an
                                                                                                              ROE of 9.04%. Timing of an MPUC ruling is
                                                                                                              uncertain.
                                                                                                              In November 2019, NSP-Minnesota filed the 2020
                                                                                                              RES Rider with the MPUC. The requested amount
  2020 RES             Electric                   $102                November 2019           Pending         includes a true-up for the 2019 rider of $38
                                                                                                              million and the 2020 requested amount of $64
                                                                                                              million. The filing included an ROE of 9.06%.
                                                                                                              Timing of an MPUC ruling is uncertain.


NSP-Minnesota - Minnesota Resource Plan - In July 2019, NSP-Minnesota filed its
Minnesota resource plan, which runs through 2034. The plan would result in an
80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to
achieving its vision of being 100% carbon-free by 2050.
In June 2020, NSP-Minnesota filed a supplement to its resource plan, including
new modeling scenarios required by the MPUC. The updated preferred resource plan
reflects the following:
•Retirement of all coal generation by 2030 with reduced operations at some units
prior to retirement, including the early retirement of the King coal plant (511
MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
•Extending the life of the Monticello nuclear plant from 2030 to 2040;
•Continuing to run the Prairie Island nuclear plant through current end of life
(2033 and 2034);
•Construction of the Sherco combined cycle natural gas plant;
•The addition of 3,500 MW of solar;
•The addition of 2,250 MW of wind;
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage,
demand response etc.);
•Achieving 780 GWh in energy efficiency savings annually through 2034; and
•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW
of demand response by 2034.
Initial comments are due Oct. 30, 2020 and reply comments are due Jan. 15, 2021.
The MPUC is anticipated to make a final decision in the first half of 2021.

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Minnesota Relief and Recovery - In 2020, the MPUC opened a Relief and Recovery
docket and invited utilities in the state to submit potential projects that
would create jobs and help jump start the economy to offset the impacts of
COVID-19. In June 2020, NSP-Minnesota filed a Relief & Recovery proposal which
identified approximately $3 billion of capital investment which may assist in
Minnesota's economic recovery from COVID-19. The filing included the following
components:
•A wind repowering solicitation that could result in 800 to 1,000 MW with an
estimated incremental investment of $1.0 to $1.4 billion;
•A 460 MW solar facility with an incremental investment of approximately $650
million;
•Incremental electric vehicle investment and rebates with an estimated cost of
$155 million;
•Accelerated transmission investment of $180 million;
•Accelerated distribution investment of $615 million; and
•Accelerated natural gas investment of $50 million.
The MPUC scheduled a planning meeting to determine the procedural process and
next steps.
NSP-Minnesota - Mower Wind Facility - In August 2019, NSP-Minnesota filed a
petition with the MPUC to acquire the Mower wind facility from affiliates of
NextEra Energy, Inc. The facility is currently contracted under a PPA with
NSP-Minnesota through 2026. Mower is expected to continue to have approximately
99 MW of capacity following a planned repowering. The acquisition would occur
after repowering, which is expected to be completed in 2020 and qualify for the
full PTC. NSP-Minnesota will need approval from both the MPUC and FERC to
complete the transaction. The MPUC is expected to rule on the request in the
third quarter of 2020.
Minnesota State ROFR Statute Complaint - In September 2017, LSP Transmission
filed a complaint in the Minnesota District Court against the Minnesota Attorney
General, MPUC and DOC. The complaint was in response to MISO assigning
NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line
from Mankato to Winnebago, Minnesota. The project is estimated to cost $140
million and projected to be in-service by the end of 2021. It was assigned to
NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a
Minnesota state ROFR statute.
The complaint challenged the constitutionality of the statute and is seeking
declaratory judgment that the statute violates the Commerce Clause of the U.S.Constitution and should not be enforced. In June 2018, the Minnesota District
Court granted Minnesota state agencies and NSP-Minnesota's motions to dismiss
with prejudice. LSP Transmission filed an appeal in July 2018. In February 2020,
the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision
to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission's petition
for rehearing.
Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the
Prairie Island plant. See Note 12 to the consolidated financial statements of
Xcel Energy's Annual Report on   Form 10-K   for the year ended Dec. 31, 2019,
for further information. The circumstances set forth in Nuclear Power Operations
and Waste Disposal included in Item 1 of Xcel Energy's Annual Report on   Form
10-K   for the year ended Dec. 31, 2019, appropriately represent, in all
material respects, the current status of nuclear power operations, and are
incorporated by reference.
NSP-Wisconsin
2019 Electric Fuel Cost Recovery - NSP-Wisconsin's electric fuel costs for 2019
were lower than authorized in rates and outside the 2% annual tolerance band,
primarily due to increased sales to other utilities compared to the forecast
used to set authorized rates. Under the fuel cost recovery rules, NSP-Wisconsin
may retain approximately $3 million of fuel costs and defer the amount of
over-recovery in excess of the 2% annual tolerance band for future refund to
customers. In March 2020, NSP-Wisconsin filed with the PSCW indicating
over-collections of approximately $10 million to customers and proposed for
refunds to be issued in September 2020.
2021 Electric Fuel Cost Recovery - In June 2020, NSP-Wisconsin filed an
application with the PSCW to update its 2021 fuel costs and return biomass fuel
savings, which would decrease retail electric rates for 2021 by approximately
$14 million. The PSCW will decide on the application later in 2020.
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PSCo

Pending and Recently Concluded Regulatory Proceedings

                                                    Amount Requested             Filing
     Mechanism              Utility Service          (in millions)                Date               Approval                       Additional Information
                                                                                  CPUC
                                                                                                                      In February 2020, PSCo filed a rate case with the
                                                                                                                      CPUC seeking a net increase to retail gas rates of
                                                                                                                      $126.8 million, reflecting a $144.5 million
                                                                                                                      increase in base rate revenue, partially offset by
                                                                                                                      $17.7 million of costs previously authorized
                                                                                                                      through the Pipeline Integrity rider. The request
                                                                                                                      was based on a 9.95% ROE, an equity ratio of
                                                                                                                      55.81% and a historic test year as of Sept. 30,
                                                                                                                      2019, adjusted for known and measurable
                                                                                                                      differences for the 12-month period ended Sept.
                                                                                                                      30, 2020. In June 2020, PSCo revised its net
                                                                                                                      increase to $121 million.
                                                                                                                      In July 2020, PSCo, the CPUC Staff and various
                                                                                                                      intervenors filed a comprehensive unopposed
                                                                                                                      settlement, which results in a net increase to
     Rate Case                Natural Gas                 $127                February 2020           Pending         retail gas rates of $77.3 million, reflecting a
                                                                                                                      $94.1 million increase in base rate revenue,
                                                                                                                      partially offset by $16.8 million of costs
                                                                                                                      previously authorized through the Pipeline
                                                                                                                      Integrity rider. The settlement is based on:
                                                                                                                      •A ROE of 9.20%;
                                                                                                                      •An equity ratio of 55.62%; and
                                                                                                                      •A historic test year as of Sept. 30, 2019,
                                                                                                                      utilizing a year-end rate base, and incorporating
                                                                                                                      a known and measurable adjustment for the Tungsten
                                                                                                                      to Black Hawk pipeline as of April 30, 2020.
                                                                                                                      Rates will be implemented on April 1, 2021 and
                                                                                                                      will be retroactively effective back to November
                                                                                                                      2020. In July 2020, the ALJ granted an unopposed
                                                                                                                      motion to schedule a hearing for Aug. 13, 2020 to
                                                                                                                      review the settlement.
                                                                                                                      In 2019, PSCo filed a request with the CPUC
                                                                                                                      seeking a net rate increase of $108.4 million,
                                                                                                                      based on a requested ROE of 10.2% and an equity
                                                                                                                      ratio of 55.6%.
                                                                                                                      In February 2020, the CPUC issued a written
                                                                                                                      decision, resulting in an estimated $34.9 million
                                                                                                                      net base rate revenue increase. The CPUC decision
                                                                                                                      included a 9.3% ROE, an equity ratio of 55.61%,
                                                                                                                      based on a current test year ended Aug. 31, 2019,
                                                                                                                      implementation of decoupling in 2020 and other
                                                                                                                      items.
     Rate Case                 Electric                   $158                  May 2019             Received         In May 2020, the CPUC deliberated on PSCo's
                                                                                                                      request for rehearing and revised its prior
                                                                                                                      decision on the test year calculation, return on
                                                                                                                      prepaid pension and medical assets, a disallowance
                                                                                                                      of a capital investment for the Comanche Unit 3
                                                                                                                      superheater and Board compensation. In July 2020,
                                                                                                                      the CPUC's written decision was received. As a
                                                                                                                      result, electric rates will increase approximately
                                                                                                                      $12 million, retroactive back to Feb. 25, 2020. In
                                                                                                                      addition, as a part of the rehearing, the CPUC
                                                                                                                      plans to discuss the merits of opening an
                                                                                                                      investigation of Comanche Unit 3 performance.
                                                                                                                      In April 2019, PSCo filed an appeal seeking
                                                                                                                      judicial review of the CPUC's prior
                                                                                                                      ruling regarding PSCo's last natural gas rate case
                                                                                                                      (approved in December 2018). The appeal requested
                                                                                                                      review of the following: denial of a return on
                                                                                                                      the prepaid pension and retiree medical
                                                                                                                      assets; the use of a capital structure not based
                                                                                                                      on the actual historical test year; and use of an
  Rate Case Appeal            Natural Gas                 N/A                  April 2019             Pending         average rate base methodology rather than a
                                                                                                                      year-end rate base methodology.
                                                                                                                      In March 2020, The District Court of Denver County
                                                                                                                      ruled in favor of allowing the prepaid pension
                                                                                                                      assets to be included in rate base; but it upheld
                                                                                                                      the CPUC treatment of the retiree medical assets
                                                                                                                      and capital structure methodology. The CPUC did
                                                                                                                      not appeal the decision allowing inclusion of the
                                                                                                                      prepaid pension assets in rate base.


PSCo 2020 Rider Filings
In July 2020, PSCo filed Wildfire and Advanced Grid rider requests with the CPUC
instead of filing a comprehensive electric rate case in 2020.
Wildfire Protection Rider - Seeks to establish a Wildfire Protection Rider to
recover incremental costs associated with system investments to reduce wildfire
risk. The rider would be effective no later than June 2021 and continue through
2025. Wildfire Protection capital additions are projected to total approximately
$325 million. Forecasted annual revenue requirements from 2021 through 2025 are
as follows:
(Millions of Dollars)                         2021       2022       2023       2024       2025
Forecasted annual revenue requirement        $ 17$ 24$ 29

$ 32$ 34




Advanced Grid Rider - Seeks to establish an Advanced Grid Rider to recover
incremental costs associated with the Advanced Grid Intelligence and Security
Initiative (AGIS). The rider would be effective no later than May 2021 and
continue through 2025. The PSCo portion of the AGIS initiative is projected to
total approximately $850 million of capital additions. Forecasted annual revenue
requirements from 2021 through 2025 are as follows:
(Millions of Dollars)                         2021       2022       2023       2024       2025
Forecasted annual revenue requirement        $ 53$ 69$ 83

$ 89$ 99



PSCo - Comanche Unit 3
PSCo is part owner of Comanche Unit 3, a 750 MW, coal-fueled electric generating
unit. PSCo is the operating agent under the joint ownership agreement. In June
2020, the unit experienced loss of turbine oil during start-up which damaged the
plant. It is currently anticipated that Comanche Unit 3 will recommence
operations in the fourth quarter of 2020. Replacement and repair of damaged
systems in excess of a $2 million deductible are expected to be recovered
through insurance policies. PSCo has obtained replacement power for a portion of
the unit's output through purchase power agreements.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an
electric municipal utility, subject to certain conditions. Subsequently, there
have been various legal proceedings in multiple venues with jurisdiction over
Boulder's plan. In 2014, the Boulder City Council passed an ordinance to
establish an electric utility. PSCo challenged the formation of this utility and
the Colorado Court of Appeals ruled in PSCo's favor, vacating a lower court
decision. In June 2018, the Colorado Supreme Court rejected Boulder's request to
dismiss the case and remanded it to the Boulder District Court. The case was
then settled in June 2019 after Boulder agreed to repeal the ordinance
establishing the utility.

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Boulder has filed multiple separation applications with the CPUC, which have
been challenged by PSCo and other intervenors. In September 2017, the CPUC
issued a written decision, agreeing with several key aspects of PSCo's position.
The CPUC has approved the designation of some electrical distribution assets for
transfer, subject to Boulder completing certain filings.
In the fourth quarter of 2018, the Boulder City Council also adopted an
Ordinance authorizing Boulder to begin negotiations for the acquisition of
certain property or to otherwise condemn that property after Feb. 1, 2019. In
the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire
certain electric distribution assets. In the third quarter of 2019, Boulder
filed its condemnation litigation, which was later dismissed by the Boulder
District Court in September 2019 on the grounds that Boulder had not completed
the pre-requisite CPUC process and filings. Boulder is currently appealing this
order. In October 2019, the CPUC approved the subsequent filings regarding asset
transfers outside of substations, reaffirmed its 2017 decision on assets outside
of substations and closed the CPUC proceeding.
In December 2019, Boulder filed a new condemnation action despite its ongoing
appeal of the last condemnation case. PSCo subsequently filed a motion to
dismiss or stay the new condemnation action. In February 2020, Boulder filed an
application under section 210 of the Federal Power Act asking FERC to order PSCo
to interconnect its facilities with a future Boulder municipal utility under
Boulder's preferred terms and conditions.
In July 2020, PSCo reached a settlement with certain Boulder officials that
would end the city's effort to municipalize. The settlement, if approved, would
result in a 20-year franchise arrangement (with multiple opt-out conditions), an
energy partnership, an undergrounding agreement and establish how the
municipalization would move forward if Boulder exercised an opt-out. The
settlement will require approval by the Boulder City Council in August 2020 and
will further require approval by the citizens of Boulder in a ballot referendum
in November 2020.
SPS
Pending and Recently Concluded Regulatory Proceedings
                                            Amount Requested           Filing
 Mechanism          Utility Service          (in millions)              Date             Approval                      Additional Information
                                                                          NMPRC
                                                                                                          In July 2019, SPS filed an electric rate case
                                                                                                          with the NMPRC seeking an increase in retail
                                                                                                          electric base rates of approximately $51
                                                                                                          million. The rate request was based on an ROE of
                                                                                                          10.35%, an equity ratio of 54.77%, a rate base
                                                                                                          of approximately $1.3 billion and a historic
                                                                                                          test year with rate base additions through Aug.
                                                                                                          31, 2019. In December 2019, SPS revised its base
                                                                                                          rate increase request to approximately $47
                                                                                                          million, based on an ROE of 10.10% and updated
                                                                                                          information. The request also included an
                                                                                                          increase of $14.6 million for accelerated
                                                                                                          depreciation including the early retirement of
                                                                                                          the Tolk coal plant in 2032.
                                                                                                          In January 2020, SPS and various parties filed
                                                                                                          an uncontested comprehensive stipulation. The
 Rate Case             Electric                   $31                 July 2019          Received         stipulation includes a base rate revenue
                                                                                                          increase of $31 million, an ROE of 9.45% and an
                                                                                                          equity ratio of 54.77%. The stipulation also
                                                                                                          includes an acceleration of depreciation on the
                                                                                                          Tolk coal plant to reflect early retirement in
                                                                                                          2037, which results in a total increase in
                                                                                                          depreciation expense of $8 million. The parties
                                                                                                          to the stipulation agreed not to oppose the full
                                                                                                          application of depreciation rates associated
                                                                                                          with the 2032 retirement date in SPS' next base
                                                                                                          rate case. On May 11, 2020, the Hearing Examiner
                                                                                                          issued a Certification of Stipulation
                                                                                                          recommending approval of the uncontested
                                                                                                          comprehensive stipulation without modification.
                                                                                                          On May 20, 2020, the NMPRC approved the
                                                                                                          stipulation without modification. New rates and
                                                                                                          tariffs were effective beginning May 28, 2020.
                                                                           PUCT
                                                                                                          In August 2019, SPS filed an electric rate case
                                                                                                          with the PUCT seeking an increase in retail
                                                                                                          electric base rates of approximately $141
                                                                                                          million. The filing requests an ROE of 10.35%, a
                                                                                                          54.65% equity ratio, rate base of approximately
                                                                                                          $2.6 billion and utilizes a historic 12 month
                                                                                                          period that ended June 30, 2019. SPS' request
                                                                                                          was subsequently revised in March 2020 to
                                                                                                          approximately $130 million, based on a requested
                                                                                                          ROE of 10.1%, a 54.62% equity ratio, rate base
                                                                                                          of approximately $2.6 billion and historic test
                                                                                                          year ended June 30, 2019.

                                                                                                          On May 20, 2020, SPS, the PUCT Staff and various
                                                                                                          intervenors reached an uncontested settlement,
                                                                                                          which includes:
                                                                                                          •An electric rate increase of $88 million and a
                                                                                                          reset of the Transmission Cost Recovery Factor
                                                                                                          to zero;
                                                                                                          •ROE of 9.45% and equity ratio of 54.62% for
                                                                                                          AFUDC purposes;
 Rate Case             Electric                   $141               August
2019          Pending         •Depreciation rates:
                                                                                                          •Tolk - 2037 end-of-life date;
                                                                                                          •Hale - 25-year end-of-life date;
                                                                                                          •All other generating units - end-of-life dates
                                                                                                          as proposed by SPS; and
                                                                                                          •Transmission - 35% of the incremental change
                                                                                                          between existing depreciation rates and rates
                                                                                                          proposed by SPS.
                                                                                                          •Ring-fencing measures like those in other
                                                                                                          recent PUCT settlements, including:
                                                                                                          •Credit agreements and indentures (e.g., no
                                                                                                          cross-default provisions);
                                                                                                          •Financial covenants;
                                                                                                          •Restrictions on pledging of assets and securing
                                                                                                          debt;
                                                                                                          •Maintaining stand-alone credit facility and
                                                                                                          ratings; and
                                                                                                          •Affiliate and non-affiliate limitations.
                                                                                                          Final rates are expected to be retroactively
                                                                                                          applied as of Sept. 12, 2019. A decision from
                                                                                                          the PUCT is anticipated in the third quarter of
                                                                                                          2020.



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Texas State ROFR Litigation - In May 2019, the Governor signed into law Senate
Bill 1938, which grants incumbent utilities a ROFR to build transmission
infrastructure when it directly interconnects to the utility's existing
facility. In June 2019, a complaint was filed in the United States District
Court for the Western District of Texas claiming the new ROFR law to be
unconstitutional. In February 2020, the federal court complaint was dismissed by
the district court. In March 2020, the district court ruling was appealed to the
United States Court of Appeals for the Fifth Circuit. The parties are awaiting a
decision.
Texas Fuel Refund - Fuel and purchased power costs are recoverable in Texas
through a fixed fuel factor, which is part of SPS' rates. The PUCT rule requires
refunding or surcharging of under and over-recovered amounts, including
interest, when they exceed 4% of the utility's annual fuel costs.
SPS' 2019 total fuel and purchased power costs were over-collected by
approximately $39 million. As a result, SPS filed a request with the PUCT to
refund the amount to customers. In April 2020, interim rates were granted by a
Texas ALJ. This case is pending final review and approval by the PUCT.
New Mexico FPPCAC Continuation - In October 2019, SPS filed an application to
the NMPRC to approve SPS' continued use of its FPPCAC and for reconciliation of
fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will
determine whether all fuel costs incurred are eligible for recovery. SPS also
proposed that it annually review its average New Mexico Deferred Fuel and
Purchased Power balance and requests the NMPRC approve an Annual Deferred Fuel
Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel
and Purchased Power balance within a bandwidth of plus or minus 5% of annual New
Mexico fuel and purchased power costs. A public hearing is scheduled to begin on
Aug. 20, 2020.
                                 Environmental


Environmental Regulation
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires
states to develop plans for greenhouse gas reductions from coal-fired power
plants. The state plans, due to the EPA in July 2022, will evaluate and
potentially require heat rate improvements at existing coal-fired plants. It is
not yet known how these state plans will affect our existing coal plants, but
they could require substantial additional investment, even in plants slated for
retirement. Xcel Energy believes, based on prior state commission practice, the
cost of these initiatives or replacement generation would be recoverable through
rates.
Derivatives, Risk Management and Market Risk


We are exposed to a variety of market risks in the normal course of business.
Market risk is the potential loss that may occur as a result of adverse changes
in the market or fair value of a particular instrument or commodity. All
financial and commodity-related instruments, including derivatives, are subject
to market risk.
See Note 8 to the consolidated financial statements for further discussion of
market risks associated with derivatives.
Xcel Energy is exposed to the impact of adverse changes in price for energy and
energy-related products, which is partially mitigated by the use of commodity
derivatives. In addition to ongoing monitoring and maintaining credit policies
intended to minimize overall credit risk, management takes steps to mitigate
changes in credit and concentration risks associated with its derivatives and
other contracts, including parental guarantees and requests of collateral. While
we expect that the counterparties will perform under the contracts underlying
its derivatives, the contracts expose us to some credit and non-performance
risk.
Distress in the financial markets may impact counterparty risk, the fair value
of the securities in the nuclear decommissioning fund and pension fund and Xcel
Energy's ability to earn a return on short-term investments.
Commodity Price Risk - We are exposed to commodity price risk in our electric
and natural gas operations. Commodity price risk is managed by entering into
long- and short-term physical purchase and sales contracts for electric
capacity, energy and energy-related products and fuels used in generation and
distribution activities. Commodity price risk is also managed through the use of
financial derivative instruments. Our risk management policy allows it to manage
commodity price risk within each rate-regulated operation per commission
approved hedge plans.
Wholesale and Commodity Trading Risk - Xcel Energy conducts various wholesale
and commodity trading activities, including the purchase and sale of electric
capacity, energy, energy-related instruments and natural gas-related
instruments, including derivatives. Our risk management policy allows management
to conduct these activities within guidelines and limitations as approved by its
risk management committee.
Fair value of net commodity trading contracts as of June 30, 2020:
                                                                                  Futures / Forwards Maturity
(Millions of Dollars)                     Less Than 1 Year          1 to 3 Years         4 to 5 Years         Greater Than 5 Years         Total Fair Value
NSP-Minnesota (a)                       $            -             $        -           $        3           $              3             $            6
NSP-Minnesota (b)                                    -                     (2)                  (4)                        (5)                       (11)

PSCo (b)                                            (1)                   (40)                 (15)                         -                        (56)
                                        $           (1)            $      (42)$      (16)          $             (2)            $          (61)


                                                                                       Options Maturity
(Millions of Dollars)                    Less Than 1 Year         1 to 3 Years          4 to 5 Years          Greater Than 5 Years         Total Fair Value
NSP-Minnesota (b)                       $          -             $        3            $        -            $             -              $          3
PSCo (b)                                           -                     (1)                    -                          -                        (1)
                                        $          -             $        2            $        -            $             -              $          2


(a) Prices actively quoted or based on actively quoted prices.
(b) Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of
margin-sharing for the six months ended June 30:
(Millions of Dollars)                                                        2020             2019

Fair value of commodity trading net contract (liabilities) assets outstanding at Jan. 1

                                                     $   (59)$    17
Contracts realized or settled during the period                                (7)              (8)

Commodity trading contract additions and changes during the period

     7                7
Fair value of commodity trading net contract (liabilities) assets
outstanding at June 30                                                    $   (59)$    16


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At June 30, 2020, a 10% increase in market prices for commodity trading
contracts would increase pre-tax income from continuing operations by
approximately $12 million, whereas a 10% decrease would decrease pre-tax income
from continuing operations by approximately $12 million. At June 30, 2019, a 10%
increase in market prices for commodity trading contracts would decrease pre-tax
income from continuing operations by approximately $2 million, whereas a 10%
decrease would increase pre-tax income from continuing operations by
approximately $2 million.
The utility subsidiaries' commodity trading operations measure the outstanding
risk exposure to price changes on contracts and obligations that have been
entered into, but not closed, using an industry standard methodology known as
Value at Risk (VaR). VaR expresses the potential change in fair value on the
outstanding contracts and obligations over a particular period of time under
normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding
both non-derivative transactions and derivative transactions designated as
normal purchase, normal sales, calculated on a consolidated basis using a Monte
Carlo simulation with a 95% confidence level and a one-day holding period, were
as follows:
(Millions of Dollars)        Three Months Ended June 30       VaR Limit      Average       High        Low
2020                       $                   0.8           $    3.0$  0.9$ 1.1$ 0.6
2019                                           1.1                3.0          0.9         1.3         0.7


Nuclear Fuel Supply - NSP-Minnesota has contracted for approximately 51% of its
2020 enriched nuclear material requirements from sources that could be impacted
by sanctions against entities doing business with Iran. Those sanctions may
impact the supply of enriched nuclear material supplied from Russia. Long-term,
through 2030, NSP-Minnesota is scheduled to take delivery of approximately 30%
of its average enriched nuclear material requirements from these sources.
Alternate potential sources provide the flexibility to manage NSP-Minnesota's
nuclear fuel supply. NSP-Minnesota periodically assesses if further actions are
required to assure a secure supply of enriched nuclear material.
Interest Rate Risk - Xcel Energy is subject to interest rate risk. Our risk
management policy allows interest rate risk to be managed through the use of
fixed rate debt, floating rate debt and interest rate derivatives such as swaps,
caps, collars and put or call options.
At June 30, 2020 and 2019, a 100-basis-point change in the benchmark rate on
Xcel Energy's variable rate debt would impact pre-tax interest expense annually
by approximately $14 million and $17 million, respectively.
See Note 8 to the consolidated financial statements for a discussion of Xcel
Energy Inc. and its subsidiaries' interest rate derivatives.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC.
The nuclear decommissioning fund is subject to interest rate risk and equity
price risk. The fund is invested in a diversified portfolio of cash equivalents,
debt securities, equity securities, and other investments. These investments may
be used only for purpose of decommissioning NSP-Minnesota's nuclear generating
plants.


Realized and unrealized gains on the decommissioning fund investments are
deferred as an offset of NSP-Minnesota's regulatory asset for nuclear
decommissioning costs. Fluctuations in equity prices or interest rates affecting
the nuclear decommissioning fund do not have a direct impact on earnings due to
the application of regulatory accounting.
Changes in discount rates and expected return on plan assets impact the value of
pension and postretirement plan assets and/or benefit costs.
Credit Risk - Xcel Energy is also exposed to credit risk. Credit risk relates to
the risk of loss resulting from counterparties' nonperformance on their
contractual obligations. Xcel Energy maintains credit policies intended to
minimize overall credit risk and actively monitor these policies to reflect
changes and scope of operations.
At June 30, 2020, a 10% increase in commodity prices would have resulted in an
increase in credit exposure of $27 million, while a decrease in prices of 10%
would have resulted in a decrease in credit exposure of $2 million. At June 30,
2019, a 10% increase in commodity prices would have resulted in an increase in
credit exposure of $14 million, while a decrease in prices of 10% would have
resulted in an increase in credit exposure of $16 million.
Xcel Energy conducts credit reviews for all counterparties and employs credit
risk control, such as letters of credit, parental guarantees, master netting
agreements and termination provisions. Credit exposure is monitored and when
necessary, the activity with a specific counterparty is limited until credit
enhancement is provided. Distress in the financial markets could increase our
credit risk.
FAIR VALUE MEASUREMENTS


Xcel Energy uses derivative contracts such as futures, forwards, interest rate
swaps, options and FTRs to manage commodity price and interest rate risk.
Derivative contracts, with the exception of those designated as normal
purchase-normal sale contracts, are reported at fair value.
The Company's investments held in the nuclear decommissioning fund, rabbi
trusts, pension and other postretirement funds are also subject to fair value
accounting.
See Note 8 to the consolidated financial statements for further discussion of
the fair value hierarchy and the amounts of assets and liabilities measured at
fair value that have been assigned to Level 3.
Commodity Derivatives - Xcel Energy monitors the creditworthiness of the
counterparties to its commodity derivative contracts and assesses each
counterparty's ability to perform on the transactions. The impact of discounting
commodity derivative assets for counterparty credit risk was not material to the
fair value of commodity derivative assets at June 30, 2020.
Adjustments to fair value for credit risk of commodity trading instruments are
recorded in electric revenues. Credit risk adjustments for other commodity
derivative instruments are deferred as other comprehensive income or deferred as
regulatory assets and liabilities. Classification as a regulatory asset or
liability is based on commission approved regulatory recovery mechanisms. The
impact of discounting commodity derivative liabilities for credit risk was
immaterial at June 30, 2020.
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